The Idaho Public Utilities Commission has approved changes
in the way the annual Power Cost Adjustment (PCA) is calculated in hopes of
decreasing the volatility in the rate adjustment, which can be either a
one-year surcharge on customer bills or a one-year credit.

The normal costs for supplying power to customers
are recovered in a utility’s base rates. However, a utility may incur higher
than normal costs from unusual circumstances, such as low-water conditions or
higher than anticipated market conditions. In those circumstances, the
commission approved a PCA process that enables Idaho utilities to recover
higher than normal costs. Revenues from a PCA surcharge are used only to pay
the increased power costs and do not increase company earnings.

The
PCA becomes effective June 1 every year. Because water conditions have been
lower than normal and the market more volatile, customers have experienced wide
variations in the PCA in recent years. The 2008 PCA was an average 10.7 percent
increase for customers. In 2007, the surcharge was an average 14.5 percent increase.
However, in 2006, there was an average 19.34 percent credit or decrease to
customer rates.

To address the fluctuations in the PCA, the commission
directed Idaho Power Co., commission staff and representative of customer
groups to participate in workshops. Customer groups participating included
those representing commission staff, Idaho Power, irrigation customers,
industrial customers, Micron and the U.S. Department of Energy. The workshops
resulted in a settlement agreed to by all parties and later approved by the
commission.

Major components of the agreement include:

1) Since the 1992
inception of the PCA, 10 percent of the power supply costs above base rates
were absorbed by the company and customers paid the remaining 90 percent in the
form of the surcharge. Conversely, during those years when there was a credit,
Idaho Power got 10 percent of the savings and customers received 90 percent.

The settlement adopted by the commission changes that
sharing mechanism to require customers to pay 95 percent of above-normal power
supply expense. During years when there is a credit, customers would get 95
percent of the savings. The sharing mechanism was put in place to incent the
company to make wise decisions when purchasing energy because the company would
be responsible for 10 percent of the costs of those decisions. However, since
1992, the volatility in power supply expense scenarios has increased from about
$100 million to $330 million. The settlement proposes, and the commission
agrees, that with a 95/5 share, the company’s risk and possible loss would be
about the same proportionately as it was under the 90/10 share. “We do find
that power supply cost volatility has increased significantly since the PCA was
implemented, and that with increased volatility , a sharing percentage of 5
percent still provides strong incentive for the company to make prudent power
purchases,” the commission said.

A further reason for the change to 95/5 is that after the
2000-01 Western energy crisis, the commission directed Idaho Power to develop a
risk management policy that provides less discretion to Idaho Power when making
its energy sales and purchases.

2) The settlement
also adopts changes in the Load Growth Adjustment Rate, or LGAR. The LGAR
acknowledges that Idaho Power’s revenues will increase between rate cases due
to customer growth and changes in customer use. About $31.40 per megawatt-hour
was subtracted from power supply expense to account for that growth. The
settlement’s new methodology recognizes that the company also incurs additional
power supply costs to serve new load between rate cases and has no opportunity
to collect those costs. Therefore, the settlement reduces the LGAR to $28.14
per MWh.

3) A third
component of the settlement makes changes to the formula for determining
forecasted power supply expenses. The former methodology created unreasonably
large true-ups between forecasted power supply costs and actual costs. The new
method is designed to reduce that difference.

4) A fourth
component allows Idaho Power to include third-party transmission expense in the
PCA not already included in base rates. During 2007, third-party transmission
costs were about $13 million. “We find that third-party transmission costs are
incurred in conjunction with market purchase and sales and should be tracked
through the PCA, like other variable power supply costs,” the commission said.